The invention may be applied to a variety of different hydrocarbon conversion reactions. Some of these reactions may be described in simple terms such as A+B→C+D; or E→F; or G→H+I; or J+K→L. Additional reactants may be used or additional products may be generated depending upon the specific reaction. However, to benefit from the present invention, the reactions are being conducted in the liquid phase and are catalyzed by a solid catalyst operated in the moving bed mode. At least one reactant is continuously introduced to the moving bed of catalyst containing a sufficient amount of catalyst effective to catalyze the reaction. The reactant(s) are in the liquid phase, and the reactant(s) may be present in a mixture with a liquid fluid carrier. The moving bed of catalyst is operated at conditions optimal to the desired reaction. As the reactant(s) contacts the catalyst, the hydrocarbon conversion reaction occurs to form at least one product. When chemical equilibrium is reached, the ratio of the concentrations of the reactants and products remain constant, and no increase in the concentrations of product(s) are accomplished. If the hydrocarbon conversion reaction is not equilibrium limited, the reaction may continue to a desired endpoint. The process is continuous, with reactant continuously being introduced, product being continually removed, and the catalyst bed continuously moving.
Numerous variations of this simple illustration will be apparent to one skilled in the art. For example, one would understand how to apply this invention to liquid phase hydrocarbon conversion processes such as cracking, hydrocracking, alkylation of aromatics, alkylation of isoparaffins, isomerization, polymerization, reforming, dewaxing, hydrogenation, dehydrogenation, transalkylation, dealkylation, hydration, dehydration, hydrotreating, hydrodenitrogenation, hydrodesulfurization, ring opening, and hydroprocessing processes.
For ease of understanding, the details of the invention will be discussed herein in terms of an alkylation reaction, which is the reaction between a feed hydrocarbon and an alkylating agent. Hydrocarbon alkylation is widely used in the petroleum refining and petrochemical industries to produce a variety of useful acyclic and cyclic hydrocarbon products used as motor fuel, plastic and detergent precursors and petrochemical feedstocks.
In the production of motor fuels, the feed hydrocarbon is typically isobutane (I) and the alkylating agent is typically olefin (O). It is preferred to operate with an excess of isobutane in compared to olefin in order to promote the preferred alkylation reaction (I+O=Alkylate) instead of the undesirable oligomerization reaction (O+O=oligomer).
For example, large amounts of high octane gasoline are produced commercially by alkylation of isobutane with butenes or propylene. This significantly increases the value of the C4 feed hydrocarbons. Additionally, large amounts of valuable alkyl aromatic hydrocarbons including cumene, ethylbenzene and C10 to C15 linear alkylaromatics are produced by the alkylation of benzene with olefins of the appropriate carbon number.
Historically, liquid-acid alkylation processes have been used commercially, and such processes commonly employ hydrofluoric acid (HF) or sulfuric acid (H2SO4) as catalysts. Environmental and safety concerns, among other factors, have led to the development of alkylation processes utilizing solid catalysts. However, solid alkylation catalysts tend to have relatively quick deactivation times (e.g., about 2-24 hours) and require frequent regeneration.
Known liquid acid alkylating processes are typically designed with external isobutane to olefin ratios (I/O) between 5/1 and 15/1. External I/O is defined as total isobutane to the reaction section divided by the total feed olefin. It is desirable to have a solid catalyst alkylation process with the same range of external I/O ratios to remain cost competitive to liquid acid alkylation. The I/O ratio can be increased further inside the reactor section by recycling isobutane. This Internal I/O is defined as the local isobutane to local olefin concentration. The internal I/O ratio can also be increased by dividing the olefin feed into multiple injections, and requires mixing to ensure the feed olefin is completed dispersed in the reaction liquid stream. For solid catalyst alkylation, higher internal I/O ratios will result in longer catalyst lives and an improved product quality, but will also increase the capital and operating costs of the process.
With respect to solid catalyst alkylation, moving bed solid catalyst alkylation processes have a number of advantages over fixed bed solid catalyst alkylation processes, as described, for example, in U.S. Pat. No. 5,849,976 to Gosling, et al. at Col 2, lines 66-67 and Col 3, lines 1-9, which explains that the use of moving bed reactors has the advantage of reducing both the catalyst and liquid hydrocarbon inventory in the plant, which are desirable cost and safety benefits, and also that use of moving beds can function to transfer the catalyst between reaction and regeneration zones, which has the benefit of allowing the catalyst to be partially or totally replaced without disrupting the operation of the process. The U.S. Pat. No. 5,849,976 describes, for example, the utilization of slowly moving cylindrical beds of solid catalyst in a process featuring a cooling zone within the reaction zone and a moving bed catalyst regeneration zone. U.S. Pat. No. 5,849,976 at Abstract. Additionally, U.S. Pat. No. 3,838,038 to Greenwood et al. describes a method of operating a continuous hydrocarbon process employing solid catalyst particles that includes a moving bed reaction zone and a continuous regeneration zone. U.S. Pat. No. 3,838,038 at Col. 2 lines 25-30.
Another specific hydrocarbon conversion process likely to benefit from this invention is hydroprocessing.
Petroleum refiners often produce desirable products such as turbine fuel, diesel fuel, middle distillates, naphtha, and gasoline boiling hydrocarbons among others by hydroprocessing a hydrocarbon feed stock derived from crude oil or heavy fractions thereof. Hydroprocessing can include, for example, hydrocracking, hydrotreating, hydrodesulfurization and the like. Feed stocks subjected to hydroprocessing can be vacuum gas oils, heavy gas oils, and other hydrocarbon streams recovered from crude oil by distillation. For example, a typical heavy gas oil comprises a substantial portion of hydrocarbon components boiling above about 371° C. (700° F.) and usually at least about 50 percent by weight boiling above 371° C. (700° F.), and a typical vacuum gas oil normally has a boiling point range between about 315° C. (600° F.) and about 565° C. (1050° F.).
Hydroprocessing is a process that uses a hydrogen-containing gas with suitable catalyst(s) for a particular application. In many instances, hydroprocessing is generally accomplished by contacting the selected feed stock in a reaction vessel or zone with the suitable catalyst under conditions of elevated temperature and pressure in the presence of hydrogen as a separate phase in a three-phase system (gas/liquid/solid catalyst). Such hydroprocessing is commonly undertaken in a trickle-bed reactor where the continuous phase is gaseous and not liquid.
In the trickle bed reactor, an excess of the hydrogen gas is present in the continuous gaseous phase. In many instances, a typical trickle-bed hydroprocessing reactor requires up to about 1778 nm3/m3 (10,000 SCF/B) of hydrogen at pressures up to 17.3 MPa (2500 psig) to effect the desired reactions. However, even though the trickle bed reactor has a continuous gaseous phase due to the excess hydrogen gas, it is believed that the primary reactions are taking place in the liquid-phase in contact with the catalyst, such as in the liquid filled catalyst pores. As a result, for the hydrogen gas to get to the active sites on the catalyst, the hydrogen must first diffuse from the gas phase into the liquid-phase and then through the liquid to the reaction site adjacent the catalyst.
While not intending to be limited by theory, under some hydroprocessing conditions the hydrogen supply available at the catalytic reaction site may be a rate limiting factor in the hydroprocessing conversions. For example, hydrocarbon feed stocks can include mixtures of components having greatly differing reactivities. While it may be desired, for example, to reduced the nitrogen content of a vacuum gas oil to very low levels prior to introducing it as a feed to a hydrocracking reactor, the sulfur containing compounds of the vacuum gas oil will also undergo conversion to hydrogen sulfide. Many of the sulfur containing compounds tend to react very rapidly at the operating conditions required to reduce the nitrogen content to the desired levels for hydrocracking. The rapid reaction rate of the sulfur compounds to hydrogen sulfide will tend to consume hydrogen that is available within the catalyst pore structure thus limiting the amount of hydrogen available for other desired reactions, such as denitrogenation. This phenomenon is most acute within the initial portions (i.e., about 50 to about 75 percent) of the reaction zones. Under such circumstances with the rapid reaction rate of sulfur compounds, for example, it is believed that the amount of hydrogen available at the active catalyst sites can be limited by the diffusion of the hydrogen through the feed (especially at the initial portions of the reactor). In these circumstances, if the diffusion of hydrogen through the liquid to the catalyst surface is slower than the kinetic rates of reaction, the overall reaction rate of the desired reactions (i.e., denitrogenation, for example) may be limited by the hydrogen supply and diffusion. In one effort to overcome the limitations posed by this phenomenon (hydrogen depletion), hydroprocessing catalysts can be manufactured in small shapes such as tri-lobes and quadric-lobes where the dimension of the lobe may be on the order of 1/30 inch. However, such small catalyst dimensions also can have the shortcoming of creating larger pressure drops in the reactor due to the more tightly packed catalyst beds.
Two-phase hydroprocessing (i.e., a liquid hydrocarbon stream and solid catalyst) has been proposed to convert certain hydrocarbon streams into more valuable hydrocarbon streams in some cases. For example, the reduction of sulfur in certain hydrocarbon streams may employ a two-phase reactor with pre-saturation of hydrogen rather than using a traditional three-phase system. See, e.g., Schmitz, C. et al., “Deep Desulfurization of Diesel Oil: Kinetic Studies and Process-Improvement by the Use of a Two-Phase Reactor with Pre-Saturator,” Chem. Eng. Sci., 59:2821-2829 (2004). These two-phase systems only use enough hydrogen to saturate the liquid-phase in the reactor. As a result, the reactor systems of Schmitz et al. have the shortcoming that as the reaction proceeds and hydrogen is consumed, the reaction rate decreases due to the depletion of the dissolved hydrogen. As a result, such two-phase systems as disclosed in Schmitz et al. are limited in practical application and in maximum conversion rates.
Other uses of liquid-phase reactors to process certain hydrocarbonaceous streams require the use of diluent/solvent streams to aid in the solubility of hydrogen in the unconverted oil feed and require limits on the amount of gaseous hydrogen in the liquid-phase reactors. For example, liquid-phase hydrotreating of a diesel fuel has been proposed, but requires a recycle of hydrotreated diesel as a diluent blended into the oil feed prior to the liquid-phase reactor. In another example, liquid-phase hydrocracking of vacuum gas oil is proposed, but likewise requires the recycle of hydrocracked product into the feed to the liquid-phase hydrocracker as a diluent. In each system, dilution of the feed to the liquid-phase reactors is required in order to effect the desired reactions. Because hydrotreating and hydrocracking typically require large amounts of hydrogen to effect their conversions, a large hydrogen demand is still required even if these reactions are completed in liquid-phase systems. As a result, to maintain such a liquid-phase hydrotreating or hydrocracking reaction and still provide the needed levels of hydrogen, the diluent or solvent of these prior liquid-phase systems is required in order to provide a larger relative concentration of dissolved hydrogen as compared to unconverted oil to insure adequate conversions can occur in the liquid-phase hydrotreating and hydrocracking zones. See US Application Publication No. 2009/0095651. As such, larger and more complex liquid-phase systems are needed to achieve the desired conversions that still require large supplies of hydrogen.
Furthermore, there are distinct advantages to operating in a moving bed mode as opposed to a fixed bed mode. For example, fixed catalyst beds deactivate over time resulting in a declining level of performance. Moving beds, on the other hand, enable deactivated catalyst to be removed and fresh or regenerated catalyst to be added to the reactor to provide a continuous level of performance. Generally speaking, a moving bed operation requires less catalyst and less hydrocarbon inventory than a fixed bed operation of the same capacity, see U.S. Pat. No. 5,849,976.
Similarly, there are advantages to multiple moving bed reaction zones over a single moving bed process. Multiple reaction zone enable the liquid effluent to be mixed with additional hydrogen. Increasing the number of hydrogen mix points reduces the amount of liquid recycle. Lower liquid recycle reduces the capital and operating costs of the unit. Also, multiple reaction zone beds enable the liquid effluent from each reaction zone bed to be cooled. Increasing the number of cooling points can reduce the liquid recycle if the cooling achieved by mixing with hydrogen is not sufficient.
Although a wide variety of process flow schemes, operating conditions and catalysts have been used in commercial petroleum hydrocarbon conversion processes, there is always a demand for new methods and flow schemes that provide more useful products and improved product characteristics. In many cases, even minor variations in process flows or operating conditions can have significant effects on both quality and product selection. There generally is a need to balance economic considerations, such as capital expenditures and operational utility costs, with the desired quality of the produced products.